Steam pipelines in Kamojang operated by Pertamina Geothermal Energy.
Pertamina Geothermal Energy is in expansion mode and doing well since it went public on February 24, 2023.
PGE share price has gone up from an IPO price of 875 IDR on February 24, 2023, to 1190 IDR, an increase of 36%.
The company booked a US$406.28 million profit in 2023 compared with US$386 in 2022, an increase of 5.24%.
Pertamina Geothermal Energy says it needs 3 billion USD until 2029 to support its expansion targets.
It aims to have a total capacity of 1000 MW in 2026.
For 2024, it allocated US$547 million as its capital expenditures.
Currently, PGE operates several geothermal power plants with a total capacity of 672 MW.
It is constructing the 55 MW Lumut Balai Unit 2 geothermal plant which is expected to start operating towards the end of 2024. This project will bring the total installed capacity to 727 MW.
The company is working on the development of 55 MW Hululais Unit 1 and 55 MW Hululais Unit 2 power plants.
It is drilling development wells for Lahendong Unit 7 and Unit 8 power stations with a target COD in 2027.
While PGE is busy increasing its geothermal energy production capacity in Indonesia, it also eyeing geothermal development opportunities overseas.
In Kenya, the company is in discussion with Geothermal Development Company (GDC) on a joint development of the Suswa geothermal field.
In Turkiye, Pertamina Geothermal Energy recently signed a Non-Disclosure Agreement with Kipas Holding to develop a geothermal prospect in Turkiye.
Jamin Djuang – Chief Learning Office of LDI Training
Drilling in South Mahakam, East Kalimantan. Photo courtesy of Rick Patenaude.
Oil and gas production in Indonesia is still declining. Nevertheless, the year 2023 has been a remarkable year for the oil and gas industry in Indonesia.
Here are some of the most significant and exciting events that took place in 2023.
The completion of BP’s Tangguh LNG Train 3.
The acquisition of Shell’s interest in the Abadi LNG project by Pertamina and Petronas.
Huge gas discovery in Geng North field by ENI.
Another big gas discovery in the Andaman Sea by Mubadala and Harbour Energy in the Layaran-1 well.
With a total production of around 605,000 barrels of oil and 5400 MMSCF of gas per day from all the operators, here are the top four oil operators in 2023.
Pertamina Hulu Rokan
ExxonMobil Cepu Limited
Pertamina EP
Pertamina Hulu Mahakam
PERTAMINA HULU ROKAN
Pertamina Hulu Rokan is celebrating its 5th anniversary as the operator of the huge but declining Rokan block that it acquired from Chevron Pacific Indonesia and other oil fields in Sumatra.
In meeting its commitments to increase oil production from the Rokan block, PHR has been pulling out all the stops to maintain and even increase production from the rapidly declining oil fields.
In 2023, Pertamina produced 59 million barrels of oil from the Rokan block up from 57.3 million barrels in 2022.
The company has drilled more than 1000 development wells that helped increase its daily oil production to 167,000 barrels.
To further increase the production from the block PHR will start two enhanced oil recovery projects:
1. Chemical EOR in the Minas field – A 96 million USD project.
2. Steam flood in the Rantaubais field – A 240 million USD project.
The Rokan block is home to two giant oil fields: The Minas oil field and the famous Duri oil field. It is also home to many smaller oil fields.
EXXONMOBIL CEPU LIMITED
EMCL was the largest oil producer in Indonesia in 2022. However, its production reduced to 140,000 BOPD in 2023 also due to natural decline.
To counter the decline and to boost its production, EMCL has earmarked 203 million USD to drill 7 infill wells in 2024: with five wells targeting the carbonate formation and two wells targeting the clastic formation. Production from the new wells is expected to boost its production by 10,000 BOPD in 2025.
PERTAMINA EP
Pertamina EP produced 71,740 BOPD in 2023. Pertamina EP was established in 2005 as a subsidiary company of PT Pertamina to operate all the oil and gas fields that Pertamina had in 2005 throughout Indonesia. Some of them are very old fields acquired from BPM ( Bataafsche Petroleum Maatschappij) in 1965 and some of them are newer fields discovered and developed by Pertamina.
PERTAMINA HULU MAHAKAM
Pertamina HuluMahakam produced around 26,200 barrels of oil and 530 MMSCF of gas per day. Although its oil production may be low compared to the other three, its gas production is very significant.
PHM has been very active in increasing its oil and gas production from the Mahakam block in East Kalimantan. Three offshore rigs are currently drilling development, re-entry, and exploration wells for PHM.
EPILOGUE
As oil and gas production continues to decline, Indonesia is getting even more serious about reversing the trend. The focus in 2024 is to boost the tempo of exploration. SKK Migas said exploration spending this year will double to 1.8 billion USD from the previous year with a target of drilling 48 exploration wells.
By Jamin Djuang – Chief Learning Officer of LDI Training and author of The Story of Oil and Gas: How Oil and Gas are Explored, Drilled and Produced.
Drilling in East Kalimantan. Photo courtesy of Rick Patenaude.
Global oil production continues to increase. It increased by 1.7 million barrels per day in 2023. EIA projects it will increase by 0.6 million and 1.6 million barrels per day in 2024 and 2025 respectively.
Here are the top 20 oil-producing countries in the world in 2023 with their daily production volume and market share.
USA – 17,770,000 BOPD (18.9% market share)
Saudi Arabia – 12,136,000 BOPD (12.9%)
Russia – 11,202,000 BOPD (11.9%)
Canada – 5,576,000 BOPD (5.9%)
Iraq – 4,520,000 BOPD (4.8%)
China – 4,111,000 BOPD (4.4%)
UAE – 4,020,000 BOPD (4.3%)
Iran – 3,822,000 (4.1%)
Brazil – 3,107,000 (3.3%)
Kuwait – 3,028,000 (3.2%)
Mexico – 1,944,000 (2.1%)
Norway – 1,901,000 (2.0%)
Kazakhstan – 1,769,000 (1.9%)
Qatar – 1,768,000 (1.9%)
Algeria – 1,474,000 (1.6%)
Nigeria – 1,450,000 (1.5%)
Angola – 1,190,000 (1.3%)
Libya – 1,088,000 (1.2%)
Oman – 1,064,000 (1.1%)
UK – 778,000 (0.8%)
Source: 20 Countries That Produce the Most Oil in the World by Ali Ahmed.
In this article focusing on Indonesia, I will take a look upstream company landscape, starting with a quick review of the M&A deals in 2023 and then going through the companies that are currently involved, with the focus being on the international investors. 2023 M&A SUMMARY The early part of the year saw little in terms of M&A, with the first deal only coming in June. We then were the two “big” deals announced at July’s IPA conference. The table below summarizes the M&A deals announced in Indonesia in 2023.
INTERNATIONAL COMPANIES – THE MAJORS We saw some significant upstream exits from the majors this year, with both Shell and Chevron divesting their remaining upstream assets. However, I believe we have now reached a point where we are unlikely to see further upstream exits from the majors, with the remaining players having both anchor projects and a willingness to continue to invest.
Those remaining (and likely to remain) are: BP: have a clear reason to remain in Indonesia as operator of the Tangguh LNG project where the third train was brought onstream this year (after several delays). The approval and progress towards FID of further upstream and CCS developments at the asset continue to show good momentum. On the growth side, they have a stake in the Andaman II PSC as well as picking up the Agung I and Agung II exploration blocks.
ExxonMobil: they had been looking risky given that their only upstream asset is the Cepu PSC. However, this is a great asset and there has been a lot of positive news this year regarding their investment in Indonesia, even if the current focus looks to be CCUS and downstream.
Eni: are very focussed on the Kutei basin and have (finally) added the Rapak and Ganal PSCs this year, as well as exploration success in the basin with the Geng North well. I expect to see continued investment in the basin with a focus on maintaining production through Jangkrik and developing Geng North. However, I’m not sure they will look at other basins. The recent exits from the upstream space in Indonesia are ConocoPhillips (exit in 2021), Shell (2023), and Chevron (2023). In addition, TotalEnergies (2017/2018) are as good as gone (they just have a lingering 13.5% interest in the Sebuku PSC). I see it as very unlikely that any of the companies would re-enter.
INTERNATIONAL COMPANIES – MID-CAPS The lack of mid-caps seems to be a global issue for the upstream industry, with the industry polarized, leaving our traditional explorers with a limited buyer pool. This trend applies to Indonesia too and, whilst there are mid-caps present, they seem to have a limited view of growth.
Repsol: have divested from the rest of Southeast Asia but have held onto Indonesia. This year saw them relinquish their interest in the Andaman III PSC after the Rencong-1 well came up dry in 2022. The major interests are now the producing Corridor PSC and the potential development of the Kaliberau Dalam field in the Sakakemang PSC, targeted to be onstream by 2028. December saw the approval of the Corridor PSC being switched from gross split terms to cost recovery, which should improve the value, and now might be the right time to exit. MedcoEnergi is still the obvious buyer.
Mubadala Energy: a company that seems to have had a second wind in Indonesia. They have very limited remaining production (Ruby field / Sebuku PSC) but they have a major stake in three Andaman PSCs (Andaman I / Andaman II / South Andaman). The two big exploration successes in these blocks give them a big reason to stay, although they may look to farm down their interest in the two PSCs in which they hold 80% once they have firmed up the resource.
Harbour Energy: they have had a busy end to 2023, with the acquisition of Wintershall DEA (no assets in Southeast Asia). This brings with it a global portfolio which may change their view on Indonesia but I expect any rationalization to come later. For Indonesia, legacy production comes from the Natuna Sea Block A PSC but the portfolio now looks nicely balanced with the Tuna PSC awaiting development and the Andaman PSCs starting to prove up nicely. Hopefully, we will see Zarubezhneft divest their interest in the Tuna PSC, so Harbour can move towards FID.
Cenovus (Husky): following the merger of Husky and Cenovus, I was expecting Indonesia to be considered for divestment. However, they continue to progress with developments at their Madura Strait PSC, with an FLNG development now being proposed. They last took new exploration acreage in the 1st 2021 bid round with the Liman PSC.
INTERNATIONAL COMPANIES – SMALLER PLAYERS There have been many smaller international investors in Indonesia. However, I will put my focus on those with a more international investor base.
Jadestone Energy: is progressing nicely with the development of its Akatara gas field in the Lemang PSC, with the first gas expected in April 2024. This will bring some much-needed cashflow and, together with no further issues with their Montara field in Australia could see them set for a strong 2024. If funding allows, they could look at further acquisitions in Indonesia.
Criterium Energy: is a new entrant to Indonesia in 2022, and has continued to invest in Indonesia this year with the acquisition of Mont D’Or, where there could be decent upside potential. In addition, they recently turned a nice profit on their 2022 acquisition of the Bulu PSC (Lengo). They seem to have an appetite for further investments and I would imagine Indonesia is high up their list.
Conrad Asia Energy: after a big 2022, this year has proved more challenging for Conrad. They had been hoping to take FID on their Mako gas field developments but this seems to have hit some hurdles around the GSA and third-party pipeline access. I hope things turn around for them in 2024.
Cue Energy (NZOG subsidiary): legacy production from the Sampang PSC has been added to through bringing the PB oil field onstream in the Mahato PSC. Indonesia now contributes over 50% of its production and revenue, so it could look to expand here. It might seem strange to say it, but it could easily be argued that Indonesia provides the most investor-friendly environment for upstream growth within their current portfolio, given their other countries of operation are New Zealand & Australia. There are many smaller companies that I am keeping an eye on, particularly those that could pick up undeveloped discoveries and bring them across the line, and will be very interested to see who has agreed to acquire Criterium’s Bulu stake.
INDONESIAN DOMESTIC COMPANIES There is a very long list of domestic companies. I will just mention the two largest here, together with a new entrant that could also be labeled a small international company.
MedcoEnergi: the last few years have seen plenty of ambition and a healthy appetite for acquisitions. More recently, it has been a bit quieter, with a couple of divestments (Thailand / Vietnam) and no acquisitions. However, I still see them as an active buyer and they may well end up picking up one (or both) portions of Sapura OMV in Malaysia. I see them continuing to grow and will be linked with asset sales, both at home and in the region.
Energi Mega Persada: is the other larger Indonesian company that has picked up several PSCs. I could see them taking more trimmings from Pertamina’s domestic portfolio.
Prima Energi: have quietly appeared, with the initial award of the Bawean PSC in 2022. This year saw them acquire 100% interest in the Northwest Natuna PSC that contains the undeveloped Ande Ande Lumut heavy oil field. The field has some development challenges but, with some tweaks to the fiscal terms and development plans, there should be a way to make it economic, given the 80 MMboe resource size.
JAPANESE COMPANIES Japan has a long history with oil and gas in Indonesia, but this has significantly shrunk over the last decade. Most of the remaining interest is in the LNG export projects but some smaller holdings are also maintained.
The LNG projects with Japanese company interest are: Tangguh LNG: several Japanese companies have an interest across the three unitized PSCS including JOGMEC, JX Nippon, Mitsui, Mitsubishi, INPEX, Sojitz, and Sumitomo. I don’t see any changes likely here.
Donggi Senoro LNG: Japanese interest here is held by Mitsubishi, with an interest in both the LNG plant and the Senoro-Toili JOA. I don’t see any changes likely here. Bontang LNG: there is no direct interest in the project since INPEX lost the Mahakam Offshore PSC. However, INPEX still holds a small stake in the Sebuku PSC (Ruby field) that provides some limited feedstock, but I doubt we will see any change before the expiry of the PSC in 2027.
Abadi LNG: INPEX holds a 65% operated stake. With the project finally progressing, they could consider a farm-down of minor stakes to Japanese off-takers. Alternatively, could we see a larger stake sold to a new project partner?
On the farm-in side, Japanese companies may show an interest in the Andaman PSCs if the volumes lead to an LNG export development.
Outside of the LNG projects, we generally see shrinking interest. This year, we saw Mitsui exit from the Northwest Natuna PSC (AAL), adding to their 2022 exit from the Bulu PSC (Lengo). The limited remaining interest in non-LNG assets are: JAPEX: Holds a 25% stake in the Kangean PSC. MOECO: holds a 10% stake in the Sakakemang PSC (KBD). Both of these could be targeted for divestment.
KOREAN COMPANIES Korean companies have a shorter history within Indonesia but, again, the gas-to-LNG projects are the focus due to their offtake agreements.
There is only one gas-to-LNG project with a direct Korean company interest. Donggi Senoro LNG: Korean interest here is held by KOGAS, with an interest in both the LNG plant and the Senoro-Toili JOA. KOGAS is also an off-taker, with a contract for 0.7 mtpa of LNG. However, we have seen a price dispute surrounding the mid-term contract price paid by KOGAS which did not go in their favour. As a result, they have stated they will cut their exposure to the project, although it is not clear exactly what is meant by this (it could just be the offtake contract).
The only other Korean presence in Indonesia’s upstream came from the 2nd bid round of 2022. POSCO International: signed the Bunga PSC in July 2023 (offered in 2022).
THE REGIONAL NOCs Southeast Asia has seen the regional NOCs take an increasingly important regional role outside of their home countries. For Indonesia, PETRONAS is the main regional NOC with a significant stakeholding, whilst PTTEP is stuck waiting on the sidelines. PETRONAS: have shown a big commitment in taking a 15% stake in Abadi which adds to several PSCs they already have an interest in. They have continued to invest and are progressing their Hidayah discovery, in the North Madura II PSC, towards FID.
PTTEP: they have held an interest in the Natuna Sea Block “A” PSC since 2013 but would like to grow in Indonesia. However, there are continuing legal issues relating to the 2009 oil spill at the Montara field (in Australia, but impacted Indonesia). They will be unable to invest further until these issues are fully resolved.
This article is written by Robert Chambers. He has spent 18 years working with data, software, analysis, and insight within the upstream oil and gas industry. He has a technical engineering background and has worked across a broad spectrum of technical, commercial, and advisory roles as well as driving and managing commercial product offerings. Since 2012, he has worked in the Asia-Pacific region and brings a deep understanding of the projects and clients as well as an extensive network throughout the region.
The sun rising over East Kalimantan. Photo courtesy of Rick Patenaude.
The Discovery of the Geng North Gas Field
On October 2nd, 2023, ENI proudly revealed the monumental Geng North-1 discovery, located offshore East Kalimantan, Indonesia.
This groundbreaking achievement was realized after drilling to a total depth of 5,025m using the West Capella drillship in water depths of 1,947 meters. The well encountered a 50-meter gas column in middle Miocene sandstone with exceptional reservoir quality.
The subsequent well production test revealed an estimated capacity of 80-100 MMSCFD and 5,000-6,000 BPD of condensate. The Geng North discovery is estimated to contain in-place resources of 5 TCF of gas and 400 million barrels of condensate solidifying Geng North’s status as one of the largest global discoveries in 2023.
The Long and Winding Road That Led to The Discovery
This article delves into the intricate path that led to the awe-inspiring Geng North-1 discovery, exploring the collaborative efforts, setbacks, and expertise that shaped this remarkable exploration journey.
In 2010, PT Baruna Nusantara Energi and Niko Resources Ltd orchestrated a Joint Study with UPN University, Yogyakarta, which paved the way for the North Ganal block to be tendered as a direct offer block.
The subsequent formation of a consortium with Statoil, Eni, Niko, and GDF in 2011 secured the North Ganal Production Sharing Contract (PSC). In addition, the consortium’s working interests were divided by the geologic interests of each party defined by a seismic horizon. ENI and GDF were focused on the Pliocene and upper Miocene; Statoil and Niko were focused on the middle Miocene.
Since 2014, the working interests in the block evolved, leading to the current consortium of ENI, Neptune, and PT AEI. The collaboration showcased adaptability and unity among industry players.
In 2012, the consortium drilled the Lebah-1 well. The well is an extension of the Jangkrik discovery trend. Unfortunately, the main target was wet. A secondary target was successful, and the surrounding amplitudes could contain upwards of 500 BCF of gas.
Geng North well was delineated by previous drilling. In early 2001 Unocal drilled the Gula 1 and 2 wells (inboard of Geng North); Gula-1 had 260-ft net gas pay in Miocene slope channel sands. In 2013 a consortium of Niko Resources, Statoil, and BPE drilled the Panada-1 well (outboard of Geng North) testing for the basin floor equivalent of the Gula Miocene slope channel sands; unfortunately, the well was too outboard, and the interval was a thick sequence of siltstones. These wells set up the geologic frame for Geng North – slope channel sands inboard and distal siltstones outboard. ENI reprocessed the 3D seismic in 2015 and identified the Geng North prospect in detail.
Drilling of Geng North was delayed by the oil price crash in 2014 and ENI’s activities associated with the Jangkrik development. Geng North was rescheduled to be drilled in 2020 but the COVID pandemic delayed the drilling until 2023.
ENI, the operator of the block is the major player in the East Kalimantan deepwater. ENI has been remarkably successful in the last decade in exploration worldwide. ENI’s expertise in seismic processing and efficient deepwater drilling led to the discovery.
PT AEI, the minority partner, evolved from BNE, BPE, and Niko. The shareholders of this company have been actively exploring Indonesia since 1998. They are the key personnel who brought the first deep-water field in Asia to production, the West Seno Field, and are responsible for multiple deepwater discoveries in East Kalimantan including the project currently known as IDD. Knowledge of Indonesian geology, especially in East Kalimantan aided by fresh ideas and creativity of individuals in this small company contributed to this discovery.
It has been thirteen years since the block was carved out as a JSA till the well was drilled. It is a long winding road of an exploration journey which beyond any doubt needs perseverance from all key stakeholders.
MIGAS, the institution responsible for creating and managing the JSA, has played a pivotal role. Particularly noteworthy is MIGAS’s ability to recognize the innovative ideas put forth by the consortium applying for the JSA, as well as their astute assessment of the block’s potential. The indispensable role of SKKMIGAS, in collaboration with the operator, in overseeing and managing the North Ganal block has been instrumental in achieving this monumental discovery.
The significance of this milestone cannot be overstated, and it stands as a testament to the collective dedication and expertise of all parties involved in this exploration journey.
As more JSAs are awarded, more wells are drilled, and discoveries unfold, Indonesia moves closer to fulfilling its energy needs, ensuring prosperity for its people. The Geng North-1 discovery stands as a testament to the resilience and collaborative efforts that drive success in the dynamic world of oil and gas exploration.
This article is written by Yusak Setiawan – Country Manager of Tately.
CO2 Huff and Puff Injection well JTB – 161, Jatibarang field.
Pertamina and JOGMEC (Japan Organization for Metals and Energy Security) jointly conducted the first CO2-EOR pilot project in the Jatibarang field in West Java, Indonesia using the “huff and puff” method in October 2022.
The objectives behind the huff and puff CO2 injection are to utilize CO2 to boost petroleum recovery in the Jatibarang field, support Pertamina’s CCUS ambition, and validate the performance and response of the wells and reservoirs following a CO2 injection which will serve as an input in the development of field-scale enhanced oil recovery projects.
ABOUT THE JATIBARANG OIL FIELD
The Jatibarang oil field located in West Java was discovered in 1968 and is operated by Pertamina. The field produced around 7345 BOPD dan 50 MMSCFD of gas in 2021.
Its production peaked in 1982 and the field is expected to reach its economic limit in 2026. With a large percentage of oil remaining in the reservoir, it is considered a great candidate for enhanced oil recovery.
The Jatibarang field was chosen as the first oil field to undergo the CO2-EOR test.
THE HUFF AND PUFF PILOT CO2 EOR
In this pilot EOR using the huff and puff method, CO2 was injected into two wells: JTB-137 and JTB-161. Well JTB-137 and well JTB-161 were injected with 218 tonnes and 250 tonnes of CO2 respectively.
The huff and puff process in this pilot project consists of three stages:
Injection of CO2 – 2.5 days
Soaking – About two weeks
Production – Up to three months.
The CO2 source is from Pertamina’s Subang field which is about 100 kilometres from Jatibarang. It was transported to the Jatibarang field by trucks.
RESULTS OF THE PILOT CO2-EOR
The two test wells were reopened at the end of the soaking period.
From well JTB-137, oil production increased from 10 BOPD to 47 BOPD, a big increase of 370% while the water cut declined by 30%.
From well JTB-161, oil production went up from 22 BOPD to 72 BOPD, an increase of 227% while the water cut decreased by 23%.
The pilot EOR did not show CO2 leakage. Over 70% of the CO2 injected is assumed to remain in the reservoir while approximately 30% resurfaced.
WHAT IS NEXT?
According to Deby Halinda, Expert Research and Tech Innovation at Pertamina, following the huff and huff test, further studies are needed to assess whether there is an interference between the wells. An in-depth geochemistry study will be necessary to further investigate CO2 effects on reservoir rock and fluids such as scale occurrence, CO2 solubility in water, and asphaltene buildup.
The huge Cirata reservoir, commonly known as Waduk Cirata, located in West Java is the home of two big green energy power plants in Indonesia – the newly commissioned 192 MWp solar plant and the 1000 MW hydro power plant.
The 6200-hectare (62 Km2) reservoir is located along the River Citarum.
Based on geological surveys that began in 1922 along the River Citarum and further surveys conducted by Dutchman W. J. van Blommestien, in 1948 he identified the Cirata area as a potential site for constructing a reservoir and a hydropower plant.
The Cirata Hydro Power Plant
It was not until 1981 that Indonesia decided to construct a hydropower plant in Cirata.
To make way for the construction of the Cirata reservoir, 6335 families located in 20 villages were relocated.
The main dam of the Cirata reservoir was completed on 1 September 1987.
Initially, the MW Cirata hydropower plant was completed with 250 MW capacity in early 1988.
Its capacity was increased to 500 MW later in the same year, 750 MW in 1997, and finally 1000 MW in 1998, making it the biggest hydropower plant in Indonesia.
The Floating Cirata Solar Farm
President Joko Widodo of Indonesia inaugurated the huge floating Cirata solar farm on November 9, 2023.
The 192 megawatt peak (MWp) Cirata solar plant, the largest floating solar plant in Southeast Asia is located in Cirata reservoir in West Java. The project is a collaboration between Masdar of UAE and Indonesia’s national power company, PLN.
The solar farm, comprised of 13 clusters, is powered by 340,000 solar panels capable of supplying 768 Mwh/day of electricity to 50,000 houses. The green power plant reduces 214,000 tons of CO2 emission per year.
Currently occupying only 4% of the reservoir surface area, the plant capacity may be increased to 1000 MWp in the future.
Epilogue
Today, with the newly completed solar farm, Waduk Cirata is indeed a magnificent site to behold.
It is also a significant site as it is home to two big green energy power plants.
This article is adapted from various sources by Jamin Djuang, Chief Learning Officer of LDI Training.
Dr. Larry W. Lake of The University of Texas at Austin will present the following webinar on CO2 EOR and CCUS.
Webinar title: From CO2-EOR to CCUS
Presenter: Dr. Larry W. Lake of The University of Texas at Austin
Date: January 19, 2024
Time: 9 AM – 10 AM Texas time (UTC-6)
In this webinar, Dr. Larry Lake will discuss the following aspects of CO2, from EOR to CCUS:
Properties of CO2
Basis for CO2-EOR
Transition from CO2-EOR
Review of CCS field projects.
Dr. Lake will answer questions after the presentation.
About Dr. Larry W. Lake
Dr. Larry W. Lake is a professor in the Hildebrand Department of Petroleum and Geosystems Engineering at The University of Texas at Austin where he holds the Shahid and Sharon Ullah Chair.
He holds BSE and PhD degrees in Chemical Engineering from Arizona State University and Rice University, respectively.
He is the author or co-author of more than 150 technical papers, four textbooks, and the editor of three bound volumes.
Dr. Lake has served on the Board of Directors for the Society of Petroleum Engineers (SPE) and received the SPE/DOE IOR Pioneer Award in 2000.
He won the 1996 Anthony F. Lucas Gold Medal of the AIME, the Degolyer Distinguished Service Award in 2002, and has been a member of the US National Academy of Engineers since 1997.
Larry Lake was named a Distinguished Graduate of UT in 2022. He has been at the University of Texas since 1978.
Dr. Larry W. Lake is a professor in the Hildebrand Department of Petroleum and Geosystems Engineering at The University of Texas at Austin where he holds the Shahid and Sharon Ullah Chair.
Larry Lake holds BSE and PhD degrees in Chemical Engineering from Arizona State University and Rice University, respectively.
He is the author or co-author of more than 150 technical papers, four textbooks and the editor of three bound volumes.
Dr. Lake has served on the Board of Directors for the Society of Petroleum Engineers (SPE) and received the SPE/DOE IOR Pioneer Award in 2000.
He won the 1996 Anthony F. Lucas Gold Medal of the AIME, the Degoyer Distinguished Service Award in 2002, and has been a member of the US National Academy of Engineers since 1997.
Larry Lake was named a Distinguished Graduate of UT in 2022. He has been at the University of Texas since 1978.
A large new volume of LNG, up to 14.5 million tonnes per year, will increase the total supply of LNG in Indonesia between now and 2030. The new LNG volume will come from the following LNG production centers:
Tangguh LNG Train #3 – 3.8 MPTA in the Q4 2023.
Genting Kasuri FLNG – 1.2 MTPA in 2026
Masela Abadi LNG – 9.5 MTPA in 2029
This article looks at the new LNG production capacity between now and 2030, and how the domestic market can absorb this new LNG volume.
The objective of this market analysis is to give information and incentives to both the LNG producers and buyers – domestic and international – to start planning on how to take advantage of the new LNG volume.
Assumptions and Scenario
First, here are the numbers and scenarios used in this market analysis.
On the domestic demand side, only Jawa 1 Power is the confirmed new power demand.
The development of small-scale LNG receiving terminals is considered less likely to happen.
There will be new LNG demands from the smelters located in Bahodopi and Sumbawa.
Another potential LNG domestic consumption should come from Pertamina’s refinery fuel conversion, which will come by the end of this decade.
Due to the high prices of Indonesia’s LNG as they are indexed to oil prices, the fertilizer and downstream industries are expected to play a very minor role in the domestic LNG market.
Results of Analysis
The results of the market analysis are presented in the graphic shown in this article.
The graphic shows that once full production of LNG from the Masela Abadi plant starts in 2030, the domestic-allocated LNG volume will far exceed the domestic LNG demand.
The surplus between the domestic-allocated LNG volume and the domestic demand in 2030 amounts to around 4.3 MPTA. To put it in perspective, this amount of gas is good enough to feed a 5-GW gas-fired power plant.
Without additional infrastructures or new domestic demand for LNG in the future, the producers will have to sell it together with the export-oriented volume of around 6.5 MTPA to the international markets.
Recommendations
There will be a big surplus of LNG to meet the domestic demand in 2030. Nevertheless, the outlook for LNG is good for exports.
To increase domestic demand for LNG, new infrastructures are needed to distribute the gas.
To make LNG more absorbable to domestic markets, the LNG pricing mechanism will need to be adjusted.
Barium sulfate (BaSO4) is one type of scale that is extremely difficult to remove. It is frequently removed mechanically, with higher chances of ending up cutting or replacing the scaled part of the system.
Many BaSO4 dissolvers that can remove BaSO4 effectively are available, with the only barrier is the cost of these chemicals (especially when huge amounts are necessary).
A good alternative is the chelating agents. Polyaminocarboxyates (PAC) such as EDTA, DTPA, CDTA, and NTA have been successfully used as BaSO4 dissolvers as they are considered:
-Cheap
-Non-corrosive
-Easy to handle
– Easy to formulate and improve
Some tips to effectively remove BaSO4 using PAC at a cheap price:
■ Determine the scale deposit’s full composition, layer-wise composition is recommended.
■ DTPA is considered the most effective PAC in dissolving BaSO4, but it is more expensive than the others. So, lab dissolution studies should be conducted with various PACs since EDTA or CDTA might be enough to do the job at a cheaper price.
■ Conduct laboratory dissolution studies to determine: effective concentration, use of catalysts, best temperature, soaking time, and side effects if any.
■ Various catalysts can be used to boost PAC performance such as oxalate, thiosulfate, glycolate, maleate, succinate, and even phosphonate.
■ pH has to be >10, between 10 and 11.5, to get the best performance of PACs.
■ High temperature is recommended (> 60 OC).
■ Long soaking time is necessary. It might take days to dissolve the thick dense BaSO4 scale layer. The amorphous scale will be done in a shorter time. So, buckle up and be patient.
■ Start the cleaning with organic solvent flushing, to remove the oil film or organic deposits that might be covering the BaSO4 scale.
■ If scale analysis showed acid soluble components, you can perform inhibited acid flushing to dissolve these components. This step will make the scale layer amorphous and decrease its strength especially if these acid-soluble components are like cementing materials. A water flush might be necessary after acid flush to avoid acid residue interactions with high pH PACs main treatment.
■ Soak the dissolver for the predetermined time. But don’t give up if the first soak wasn’t that efficient, a second or maybe third soaking might be necessary. It is not magic, it’s a process.
■ Agitation or circulation is recommended if possible.
■ Mechanical aids help a lot in improving dissolution efficiency.
This article is contributed by Abdullah Hussein, author of “Essentials of Flow Assurance Solids in Oil and Gas Operations”.
The energy transition is a pathway to achieve net zero by transforming the energy sector into one that is low-carbon while maintaining energy sustainability and security—increasing and utilizing the demand for oil and gas throughout the transition while reducing greenhouse gas emissions.
Challenges of the Oil and Gas Industry in Energy Transition
The oil and gas industry is facing challenges to produce energy economically and sustainably as policymakers seek emissions reductions through carbon pricing and trading. According to the International Energy Agency (IEA), the transition of oil and gas should consider three main focus levers:
♦ Rising demand for energy due to a growing global population
♦ Affordable and reliable supplies of liquid and gas, since the industry plays a critical role in economic systems
♦ Reducing the energy emissions contribution in line with the decarbonization movement to achieve net-zero emissions.
Recommendations for the Oil and Gas Industry
According to the Atlantic Council Global Energy Center, recommended steps to support and lead the transition movement in the oil and gas industry include:
• Develop strategies for decarbonization to reduce emissions and ensure profitability
• Support policy development of clear objectives for investors
• Invest in promising projects, technologies, etc., that support achieving net zero
• Implement approaches to transition oil and gas products to low-carbon products like hydrogen (H2).
Oil and Gas Energy Transition Pathways
Pathways in the energy transition that the oil and gas industry is embarking on include:
1. Energy efficiency
2. Hydrogen system
3. Carbon capture, use, and storage (CCUS)
4. Low-carbon fuels
The energy efficiency lever can play a role in reducing emissions and enhancing energy in the power sector. Hydrocarbon facilities have a chance to utilize and convert oil and gas sources to hydrogen – a clean product – but must capture CO2 sources to achieve blue H2. The captured #CO2 sources from hydrocarbon facilities or the air can be collected in a hub to be directly used in the cement and concrete industries – just one potential opportunity to utilize captured CO2 – or stored directly underground with specific geological formations.
This article is contributed by Sonia Isabella López Kovács – Reservoir Engineer Advisor at Repsol.
Indonesia signed three oil and gas exploration and production contracts under the PSC scheme on September 21, 2023.
The three contracts are for the Akia work area, Beluga work area, and Bengara I work area. They were put up for tender by the Ministry of Energy and Mineral Resources during the first round of tender conducted in April 2023.
Here are the details of the three contracts.
AKIA WORK AREA
Location: Offshore North Kalimantan
Contractors: a consortium consisting of Armada Etan B.V. as the operator and Pexco Tarakan N.V.
Size of work area: 8394 Km2
Estimated reserves: 2 billion barrels of oil and 9 TCF of gas.
Signing bonus: 500,000 USD
Contractor’s commitments: Contractor to do 3 G&G studies, conduct 750 Km2 of seismic survey, and invest 7.7 million USD over the first three years upon signing.
BELUGA WORK AREA
Location: Offshore West Natuna
Contractor: Medco Energy Beluga
Estimated reserves: 360 million barrels of oil and 50 BCF of gas.
Signing bonus: 100,000 USD
Contractor’s commitments: Contractor to conduct 2 G&G studies, drill one exploration well, and invest 8 million USD in the first 3 years upon signing.
BENGARA I WORK AREA
Location: North Kalimantan
Contractor: TexCal Energy
Estimated reserves: 90 million barrels of oil equivalent (MMBOE)
Contractor’s commitments: Contractor to do 2 G&G studies, drill one exploration well, and invest 6.5 million USD in the first 3 years upon signing.
Signing bonus: 50,000 USD
In other news, the Ministry of Energy and Mineral Resources has put up three oil and gas work areas in Papua in its third round of tender in 2023. Indonesia is very keen to step up oil and gas exploration and production to boost its hydrocarbon production.
World’s first bulk liquefied hydogen carrier – Suiso Frontier
Suiso Frontier is the world’s first bulk liquefied hydrogen carrier in the world. The word “suiso” implies hydrogen in Japanese. Suiso Frontier is designed and manufactured by Kawasaki Heavy Industries and operated by Shell under the CO2-free Hydrogen Energy Supply-chain Technology Research Association (HySTRA) project funded by the Japanese government and various partners.
The vessel can carry up to 1,250 cubic meters of liquefied hydrogen at -253 degrees Celsius in the state-of-the-art storage tank.
The vessel completed its maiden voyage between Australia and Japan in February 2022. After it underwent refitting, the vessel is now in the next phase of the demonstration which aims to assess the performance, reliability, and integrity of the vessel’s system through more load-unload cycles and to gain more operational experience.
Here are several comments on Suiso Frontier and hydrogen as a clean fuel of the future. During the vessel’s visit to Singapore on September 3-9, 2023, Mr Teo Eng Dih, Chief Executive of the Maritime and Port Authority of Singapore (MPA) said, ” Singapore announced our National Hydrogen Strategy in late 2022. The properties of hydrogen, and its potential to be produced at scale using renewable sources, makes hydrogen a potential fuel to support the energy transition to a low and zero carbon future.”
“MPA is actively studying the use of hydrogen and its carriers as a marine fuel and welcomes the collaboration with industry players such as Kawasaki Heavy Industries and Shell, as well as our work with our research community such as the A*STAR Institute of High-Performance Computing, to bring the Suiso Frontier to Singapore. This vessel visit has helped to inform the development of safety and operational procedures, and also support further feasibility studies and preparations for the deep-sea transportation and receipt of liquefied alternative fuels.”
Mr. Shigeru Yamamoto, Executive Officer, of Hydrogen Strategy Division of Kawasaki Heavy Industries said, “We strongly believe that an international supply chain of liquefied hydrogen by marine transportation is essential to realize a carbon-neutral world. The world’s first liquefied hydrogen carrier, Suiso Frontier, showed the world that cryogenic liquefied hydrogen can be transported by ship. We are confident that liquefied hydrogen will attract even more attention from around the world in the future.”
Mr. Nick Potter, General Manager of Shell Shipping and Maritime for Asia Pacific and the Middle East, said, “Transportation through deep-sea shipping is one of the critical steps essential for unlocking the use of hydrogen as a future zero-carbon fuel. The Suiso Frontier represents a key milestone in demonstrating the technical feasibility of liquefied hydrogen shipping and Shell’s maritime leadership in this area. Shell also remains committed to the safe and efficient operations of the vessel.”
This article is adapted from the content published by the Maritime and Port Authority of Singapore (MPA).
Some hot and permeable liquid-dominated geothermal wells do not naturally self-discharge their reservoir fluid after they are drilled or shut in for some time. Non-self-discharge wells are common in conventional liquid-dominated geothermal fields.
Here are several reasons why some geothermal wells are unable to flow:
Low reservoir pressure.
Formation damage caused by drilling.
Build up of water column in the well after a long shut in period.
The long water column in the well after drilling or workover.
Poor reservoir permeability.
High-elevation terrain.
Small production casing.
After a geothermal well is drilled and completed, as a standard practice, it will be tested to determine its potential.
Before it is tested, engineers will assess whether the well will flow. For new wells, the two common analysis methods used are the Af/Ac ratio method and the water column length method.
A well is considered a non-self-discharge when the ratio of Af/Ac is less than 0.7, while a well with an Af/Ac ratio of more than 0.85 has an excellent chance to self-discharge.
Based on a study of geothermal wells with more than 200 degrees C in Indonesia, a well is likely capable to self-discharge when the length of the water column in the well is less than 600 meters, whereas if it is more than 600 m, the well may not self-discharge. The water column length is the vertical distance between the water level in the well and the depth of the feed zone.
How do you stimulate a non-self-discharge geothermal well to make it flow?
Once it is established or predicted that the newly drilled geothermal well will not or is unlikely to self-discharge, engineers will apply a stimulation technique to make the well flow.
When the well reservoir pressure is not sufficient to lift the column of water that has accumulated in the well, a well discharge stimulation technique will be applied to jump-start the well. There are five stimulation techniques to discharge the water. They are:
Air compression
Well-to-well stimulation
Nitrogen injection
Air injection
Injection of steam from a portable boiler.
If a well is unable to flow due to formation damage or low permeability, other stimulation techniques such as fracturing or acidizing may be considered.
Air Compression Stimulation Technique
Air compression stimulation is the simplest and cheapest method with a proven high success rate compared with other methods. This method does not need complicated facilities, mobilization, or installation.
One disadvantage of this method is the well casing may crack due to sudden thermal shock from the flow of hot fluids during well discharge. It should be considered with caution for wells with temperatures above 300 °C.
In this technique, an air compressor is connected to one of the wellhead side valves to inject pressurized air into the well to depress the water level and push all the cold water from the wellbore into the hot formation. This will make the hydrostatic pressure of the water column lower than the reservoir pressure. After pushing the water level below the casing shoe and allowing enough time for the cold water to heat up by the hot reservoir rock, the wellhead valve is opened quickly to create a sudden effect of buoyancy.
Here is an example of a successful application of the air compression method to stimulate a geothermal well.
Well A Case
The company wanted to test Well A. The Af/Ac ratio method was used to predict whether Well A would self-discharge. The initial Af/Ac ratio of Well A is zero and thus it was categorized as a non-self-discharge well. To stimulate the well, the air compression method was chosen.
To stimulate the well, engineers injected air into the well at a pressure of 50 Bars using a double booster compressor for 24 hours. The compressed air pushed down the water level inside the well by 500 m resulting in a final Af/Ac ratio of 2.371.
The application was successful as the well flowed by itself when the well was reopened.
Acknowledgment
This article is adapted based on the following sources:
Post by Dr. Mohamad Husni Mubarok on LinkedIn – Determining the minimum air compression pressure to stimulate the non-self-discharge geothermal well.
“Stimulation program of air compression and nitrogen injection in geothermal well” by E. Budirianto, W.A. Nugroho, B.N. Jayanto, A.H. Lukmana, D.R. Ratnaningsih
Article by Mohamad Husni Mubarok and Sadiq J. Zarrouk – Discharge Stimulation of Geothermal Wells: Overview and Analysis.
The first offshore oil platform decommissioning in Indonesia was completed in November 2022. The decommissioning of the EB platform of the giant Attaka oil field was carried out by Pertamina Hulu Kalimantan Timur as the field operator and KHAN Co. Ltd. of South Korea.
This platform decommissioning is called the Attaka Rig to Reef Project aimed to promote an effective and environmentally friendly approach to protect the ecosystem and develop future ecotourism. In the project, the platform was removed and put in a conservation area.
As many offshore oil and gas fields in Indonesia were discovered in the late 1960s and early 1970s, many of their platforms are nearing the end of their productive life, such as the ones in the Offshore North West Java block and the West Seno field according to SKK Migas.
The prolific Attaka field was discovered by Unocal along with its partner, INPEX, in 1970 in the East Kalimantan offshore working area. The Attaka field is the first commercial offshore oil field in Kalimantan. At its peak, it produced 110,000 barrels of oil and 150 MMSCF of gas per day. After more than 50 years of production, its daily oil production today has declined to less than 5000 BOPD.
Pertamina Hulu Kalimantan Timur became the field operator in October 2018.
The Gagak Rimang FSO operated by ExxonMobil Indonesia.
The two top oil operators in Indonesia account for more than 50% of the total crude oil production in Indonesia in 2023. They are Pertamina Hulu Rokan and ExxonMobil Cepu Limited.
PERTAMINA HULU ROKAN
Pertamina Hulu Rokan, the operator of the massive Rokan block, is the current largest oil producer in Indonesia.
Oil production from the Rokan block has been increasing through its ongoing massive development well drilling program since PHR acquired the block from Chevron in August 2021.
The oil production from the Rokan block went above 172,000 BOPD recently. This is the highest daily production since the acquisition.
PHR has drilled 825 development wells in the Rokan block. While the massive development drilling is continuing, PHR has started drilling the first well to explore the unconventional hydrocarbon in the Rokan block.
EXXONMOBIL CEPU LIMITED
ExxonMobil as the operator of the prolific Banyu Urip oil field in East Java produces 164,000 BOPD from the field.
EMCL was the biggest oil producer in Indonesia at one time, producing more than 200,000 BOPD during its peak. However, producing since 2008, oil production from the Banyu Urip field is declining.
To boost its production, ExxonMobil will drill five infill wells targeting the carbonate formation and two infill wells targeting the clastic formation in 2024.
This seven-well drilling of the field optimization program is expected to increase oil production by 18,000 BOPD and add 42 million barrels of oil reserve.
EMCL has contracted PDSI (Pertamina Drilling Services Indonesia) to drill the seven wells in 2024.
With an amazing 125 years of history in Indonesia, ExxonMobil is currently the oldest oil and gas operator in Indonesia. ExxonMobil started in Indonesia as Stanvac. Here is more for your reading on the history of ExxonMobil Indonesia – The Three Big Oil Companies in Indonesia before 1945 – https://oilandgascourses.org/the-three-big-oil-companies-in-indonesia-before-1945/
Currently, LNG production in Indonesia comes from three LNG plants: The Badak LNG, the Tangguh LNG, and the small 2 MTPA Donggi-Senoro LNG plant.
In the last five years, Indonesia’s LNG production volume declined by 23%, from 18.2 MTPA in 2018 to 14 MTPA in 2022 due to the declining production from the Badak LNG plant.
The Badak LNG plant, one of the largest LNG plants in the world has been in operation for 45 years since it began production in 1977 in East Kalimantan.
The Badak LNG plant comprising eight trains has a total production capacity of 22.6 MTPA. However, due to the declining gas supplies from its surrounding oil and gas fields in East Kalimantan, only two trains are now in operation.
Due to the issue of dwindling gas supplies, most of the LNG from the Badak plant is sold as short-term or spot cargoes in 2022 as it cannot secure medium and long-term deals.
The Tangguh plant is carrying the heavy load of producing the LNG for the export market. Started producing LNG in 2009, the Tangguh plant currently consists of two trains with a total production capacity of 7.6 MTPA.
Most of Indonesia’s LNG cargoes are sold in the Asia Pacific region as expected. However, thanks to the recent high LNG spot prices, some cargoes also reached European markets.
For the domestic LNG market in 2022, the “real” LNG consumption has reached 3.17 MTPA, about 23% of annual production. This number is, unfortunately, lower than the annual LNG volume consumed by some neighboring countries like Thailand (8.2 MTPA), Singapore (3.7 MTPA), and Bangladesh (4.4 MTPA).
Good progress is coming from the performance of Perta Arun Gas, which is operating the Arun LNG Regas Terminal and LNG Hub in Aceh. So far, almost one metric ton of LNG volume has been unloaded into Arun LNG tanks and later reloaded for final delivery.
FUTURE
In the future, the Tangguh and the future Masela plants will play a key role in positioning Indonesia as one of the top LNG producers with a total plant capacity of 33 MTPA.
The Tangguh Train #3 which is set to go on stream by the end of 2023 will increase the total Tangguh LNG plant capacity by 3.8 MTPA to 11.4 MTPA.
With the divestment of Shell’s interest in the Masela block, the Abadi LNG plant with a capacity of 9.5 million tons per year is expected to be completed by 2030.
Currently, up to 17 MTPA of future volume is still uncontracted. However, according to SKK Migas, there are huge interests in Indonesia’s LNG.
Fishing operation recovering a 12 1/4-inch directional drilling BHA.
Situations, where fishing is necessary, can arise during oil and gas well drilling or workover operations.
Fishing situations occur when equipment is stuck or lost in the hole. They are quite common in oil and gas well drilling or workovers. It happens to one in five wells.
While some fishing operations are simple, some of them can be very difficult or even impossible.
When fishing is impossible or deemed too difficult, the operator can opt to either redrill a new well or to sidetrack by opening a new track in the existing hole to bypass the fish.
Here are the two commonly asked questions when an operator is in a fishing situation.
Should we fish or not?
How much time should we spend to recover the fish?
Many fishing jobs are difficult and require special tools and the expertise of a fishing specialist. However, even with the best tools (which may have a high daily cost) and procedures, sometimes the fishing attempt fails or takes a long time.
It is vital to know everything possible about the fish and fishing conditions before starting the job so you can ascertain the level of difficulty. The operator should consider some fishing jobs impractical from the very start. For example, drill collars accidentally cemented in or engulfed in barite are nearly impossible to recover and are not worth the cost, even if they are recovered. In these situations, you should not proceed with fishing and should begin side-tracking instead.
When it is difficult to decide what is fishable and you do not know the probability of success, it is best to estimate the cost of side-tracking and determine how long to fish.
The cost of side-tracking can be estimated easily. It takes about 5 days to set a cement plug on top of a fish and kick off the hole to bypass the fish.
You can estimate the cost of drilling a new hole to reach the original total depth if you know the:
rate of penetration
length of the original hole.
It is also important to recognize when it is time to stop fishing and start re-drilling. You need to determine how long to fish so that the cost of the fishing operations and lost drilling time do not exceed the cost of side-tracking.
Generally, you should stop fishing and decide to sidetrack the well when the cost of fishing has reached about half the cost of side-tracking.
The following equation calculates the number of days that should be allowed for fishing.
D = (V + CS)/(R + CD)
where:
D = Number of days to be allowed for fishing
V = Replacement value of the fish
CS = Estimated cost of side-tracking
R = Daily cost of fishing tool rental and services
CD = Daily rig operating cost.
After you calculate the maximum number of days to spend fishing, you may realize that it will take longer than the allotted time to fish. In this case, it would be better off to side-track instead of attempting to fish.
This article is written by Rick Patenaude. Rick started his oilfield career in the Powder River Basin of Wyoming in the mid-1980s. He joined Weatherford as a Fishing Tool Supervisor in 1995 and worked throughout the Rocky Mountain Region until 2003. Rick transferred to China in 2003 to support Weatherford’s operations in the Pearl River Basin and Bohai Bay until 2006. Rick was then transferred to Jakarta to support the growing well-intervention market for both national and international clients. In 2012 Rick was assigned to Balikpapan as Project Manager Fishing & Re-Entry Services for Chevron’s West Seno Extended Reach Drilling Project. Upon completion of the West Seno Project Rick returned to Jakarta and began supporting operations throughout the Asia Pacific Region including New Zealand, Australia, India, Brunei, Malaysia & Japan.
The photo above shows the fish recovered with a skirted screw-in sub after a successful wash-over operation to burn off the blades on the integral bladed stabilizer. The fish is a 12-1/4″ OD directional drilling BHA.
El Salvador is one of the few countries in the world which has a high percentage of electricity produced from geothermal resources.
Its two geothermal power plants, the 95 MW Ahuachapan, and the 109 MW Berlin plants with a combined installed capacity of 204 MW, supply 21.7% of the electricity needed in the country.
The journey of geothermal development in El Salvador began with exploration in 1955 for its geothermal potential, followed by the drilling of its first geothermal well in 1968.
The country’s first 30 MW Unit 1 Ahuachapán geothermal power plant was subsequently completed in 1975.
Two more power stations were later added – 30 MW Unit 2 in 1976 and 35 MW Unit 3 in 1981 – giving the Ahuachapán power plant a total installed capacity of 95 MW.
Ahuachapán’s three power stations are supported by 21 steam production wells and 9 reinjection wells.
Following the success of the Ahuachapan plant, LaGeo, the operator began building a second plant, the Berlin geothermal plant in 1992.
The Berlin plant consisting of four power stations with a total installed capacity of 109 MW is supported by 16 steam production wells and 23 reinjection wells.
El Salvador can easily double its electricity production from geothermal resources as it still has more potential to develop. It has an estimated 600 MW of untapped geothermal resources in the following areas:
